1. Field of the Invention
The present invention relates generally to methods of drilling subterranean formations with fixed cutter-type drill bits. More specifically, the invention relates to methods of drilling, including directional drilling, with fixed cutter, or so-called xe2x80x9c drag,xe2x80x9d bits wherein the cutting face of the cutters of the bits are tailored to have different cutting aggressiveness to enhance response of the bit to sudden variations in formation hardness, to improve stability and control of the toolface of the bit, to accommodate sudden variations on weight on bit (WOB), and to optimize the rate of penetration (ROP) of the bit through the formation regardless of the relative hardness of the formation being drilled.
2. Background of the Invention
In state-of-the-art directional drilling of subterranean formations, also sometimes termed steerable or navigational drilling, a single bit disposed on a drill string, usually connected to the drive shaft of a downhole motor of the positive-displacement (Moineau) type, is employed to drill both linear (straight) and nonlinear (curved) borehole segments without tripping, or removing, the drill string from the borehole to change out bits specifically designed to bore either linear or nonlinear boreholes. Use of a deflection device such as a bent housing, bent sub, eccentric stabilizer, or combinations of the foregoing in a bottomhole assembly (BHA) including a downhole motor permit a fixed rotational orientation of the bit axis at an angle to the drill string axis for nonlinear drilling when the bit is rotated solely by the drive shaft of the downhole motor. When the drill string is rotated by a top-side motor in combination with rotation of the downhole motor shaft, the superimposed, simultaneous rotational motions cause the bit to drill substantially linearly or, in other words, causes the bit to drill a generally straight borehole. Other directional methodologies employing nonrotating BHAs using lateral thrust pads or other members immediately above the bit also permit directional drilling using drill string rotation alone.
In either case, for directional drilling of nonlinear, or curved, borehole segments, the face aggressiveness (aggressiveness of the cutters disposed on the bit face) is a significant feature, since it is largely determinative of how a given bit responds to sudden variations in bit load or formation hardness. Unlike roller cone bits, rotary drag bits employing fixed superabrasive cutters (usually comprising polycrystalline diamond compacts, or xe2x80x9c PDCsxe2x80x9d) are very sensitive to load, which sensitivity is reflected in a much steeper rate of penetration (ROP) versus weight on bit (WOB) and torque on bit (TOB) versus WOB curves, as illustrated in FIGS. 1 and 2 of the drawings. Such high WOB sensitivity causes problems in directional drilling, wherein the borehole geometry is irregular and resulting xe2x80x9csticktionxe2x80x9d of the BHA when drilling a nonlinear path renders a smooth, gradual transfer of weight to the bit extremely difficult. These conditions frequently cause downhole motor stalling and result in the loss of control of tool face orientation of the bit, and/or cause the tool face of the bit to swing to a different orientation. When control of tool face orientation is lost, borehole quality often declines dramatically. In order to establish a new tool face reference point before drilling is recommenced, the driller must stop drilling ahead, or making hole, and pull the bit off the bottom of the borehole. Such a procedure is time consuming, expensive, results in loss of productive rig time and causes a reduction in the average ROP of the borehole. Conventional methods to reduce rotary drag bit face aggressiveness include greater cutter densities, higher (negative) cutter backrakes and the addition of wear knots to the bit face.
Of the bits referenced in FIGS. 1 and 2 of the drawings, RC comprises a conventional roller cone bit for reference purposes, while FC1 is a conventional polycrystalline diamond compact (PDC) cutter-equipped rotary drag bit having cutters backraked at 20xc2x0, and FIG. 2 is the directional version of the same bit with 30xc2x0 backraked cutters. As can be seen from FIG. 2, the TOB at a given WOB for FC2, which corresponds to its face aggressiveness, can be as much as 30% less than as for FC1. Therefore, FC2 is less affected by the sudden load variations inherent in directional drilling. However, referencing FIG. 1, it can also be seen that the less aggressive FC2 bit exhibits a markedly reduced ROP for a given WOB, in comparison to FIG. 2.
Thus, it may be desirable for a bit to demonstrate the less aggressive characteristics of a conventional directional bit such as FC2 for nonlinear drilling without sacrificing ROP to the same degree when WOB is increased to drill a linear borehole segment.
For some time, it has been known that forming a noticeable, annular chamfer on the cutting edge of the diamond table of a PDC cutter has enhanced durability of the diamond table, reducing its tendency to spall and fracture during the initial stages of a drilling operation before a wear flat has formed on the side of the diamond table and supporting substrate contacting the formation being drilled.
U.S. Patent No. Re 32,036 to Dennis discloses such a chamfered cutting edge, disc-shaped PDC cutter comprising a polycrystalline diamond table formed under high-pressure and high-temperature conditions onto a supporting substrate of tungsten carbide. For conventional PDC cutters, a typical chamfer size and angle would be 0.010 of an inch (measured radially and looking at and perpendicular to the cutting face) oriented at approximately a 45xc2x0 angle with respect to the longitudinal cutter axis, thus providing a larger radial width as measured on the chamfer surface itself.
Multichamfered PDC cutters are also known in the art. For example a multichambered cutter is taught by Cooley et al., U.S. Pat. No. 5,437,343, assigned to the assignee of the present invention. In particular the Cooley et al. patent discloses a PDC cutter having a diamond table having two concentric chamfers. A radially outermost chamfer D1 is taught as being disposed at an angle xcex1 of 20xc2x0 and an innermost chamfer D2 is taught as being disposed at an angle xcex2 of 45xc2x0 as measured from the periphery, or radially outermost extent, of the cutting element. An alternative cutting element having a diamond table in which three concentric chamfers are provided thereon is also taught by the Cooley et al. patent. The specification of the Cooley et al. patent provides discussion directed toward explaining how cutting elements provided with such multiple chamfer cutting edge geometry provides excellent fracture resistance combined with cutting efficiency generally comparable to standard unchamfered cutting elements.
U.S. Pat. No. 5,443,565 to Strange Jr. discloses a cutting element having a cutting face incorporating a dual bevel configuration. More specifically in column 3, lines 35-53, and as illustrated in FIG. 5, Strange Jr. discloses a cutting element 9 having a cutting face 10 provided with a first bevel 12 and a second bevel 14. Bevel 12 is described as extending at a first bevel angle 12 with respect to the longitudinal axis of cutting element 9. Likewise, bevel 14 is described as extending at a second bevel angle 15 also measured with respect to the longitudinal axis of cutter 9. The specification, in the same above-referenced section, states that the subject cutting element had increased drilling efficiency and increased cutting element and bit life because the bevels served to minimize splitting, chipping, and cracking of the cutting element during the drilling process, which in turn resulted in decreased drilling time and expenses.
U.S. Pat. No. 5,467,836 to Grimes et al. is directed toward gage cutting inserts and depicts in FIG. 2 thereof an insert 31 having a cutting end 35 formed of a superabrasive material and which is provided with a wear-resistant face 37 thereon. Insert 31 is further described as having two cutting edges 41a and 41b with cutting edge 41b formed by the intersection of a circumferential bevel 43 and face 37 on cutting end 35. The other cutting edge 41a is formed by the intersection of a flat or planar bevel 45, face 37, and circumferential bevel 43, defining a chord across the circumference of the generally cylindrical gage insert 31. Because insert 31 is intended to be installed at the gage of a drill bit, wear-resistant face 37 is taught to face radially outwardly from the bit to provide a nonaggressive wear surface as well as to thereby allow planar bevel 45 to engage the formation as the drill bit is rotated.
U.S. Pat. No. 4,109,737 to Bovenkerk is directed toward cutting elements having a thin layer of polycrystalline diamond bonded to a free end of an elongated pin. One particular cutting element variation shown in FIG. 4G of Bovenkerk comprises a generally hemispherical diamond layer having a plurality of flats formed on the outer surface thereof According to Bovenkerk, the flats tend to provide an improved cutting action due to the plurality of edges which is formed on the outer surface by the contiguous sides of the flats.
Rounded, rather than chamfered, cutting edges are also known, as disclosed in U.S. Pat. No. 5,016,718 to Tandberg.
For some period of time, the diamond tables of PDC cutters were limited in depth or thickness to about 0.030 of an inch or less, due to the difficulty in fabricating thicker tables of adequate quality. However, recent process improvements have provided much thicker diamond tables, in excess of 0.070 of an inch, including diamond tables approaching and exceeding 0.150 of an inch. U.S. Pat. No. 5,706,906 to Jurewicz et al., assigned to the assignee of the present invention and hereby incorporated herein by this reference, discloses and claims several configurations of a PDC cutter employing a relatively thick diamond table. Such cutters include a cutting face bearing a large chamfer or xe2x80x9crake landxe2x80x9d thereon adjacent the cutting edge, which rake land may exceed 0.050 of an inch in width, measured radially and across the surface of the rake land itself. U.S. Pat. No. 5,924,501 to Tibbitts, assigned to the assignee of the present invention, discloses and claims several configurations of a superabrasive cutter having a superabrasive volume thickness of at least about 0.150 of an inch. Other cutters employing a relatively large chamfer without such a great depth of diamond table are also known.
Recent laboratory testing as well as field tests have conclusively demonstrated that one significant parameter affecting PDC cutter durability is the cutting edge geometry. Specifically, larger leading chamfers (the first chamfer on a cutter to encounter the formation when the bit is rotated in the normal direction) provide more durable cutters. The robust character of the above-referenced xe2x80x9crake landxe2x80x9d cutters corroborates these findings. However, it was also noticed that cutters exhibiting large chamfers would also slow the overall performance of a bit so equipped in terms of ROP. This characteristic of large chamfer cutters was perceived as a detriment.
It has also recently been recognized that formation hardness has a profound affect on the performance of drill bits as measured by the ROP through the particular formation being drilled by a given drill bit. Furthermore, cutters installed in the face of a drill bit so as to have their respective cutting faces oriented at a given rake angle will likely produce ROPs that vary as a function of formation hardness. That is, if the cutters of a given bit are positioned so that their respective cutting faces are oriented with respect to a line perpendicular to the formation, as taken in the direction of intended bit rotation, so as to have a relatively large back (negative) rake angle, such cutters would be regarded as having relatively nonaggressive cutting action with respect to engaging and removing formation material at a given WOB. Contrastingly, cutters having their respective cutting faces oriented so as to have a relatively small back (negative) rake angle, a zero rake angle, or a positive rake angle would be regarded as having relatively aggressive cutting action at a given WOB with a cutting face having a positive rake angle being considered most aggressive and a cutting face having a small back rake angle being considered aggressive but less aggressive than a cutting face having a zero back rake angle and even less aggressive than a cutting face having a positive back rake angle.
It has further been observed that when drilling relatively hard formations, such as limestones, sandstones, and other consolidated formations, bits having cutters which provide relatively nonaggressive cutting action decrease the amount of unwanted reactive torque and provide improved tool face control, especially when engaged in directional drilling. Furthermore, if the particular formation being drilled is relatively soft, such as unconsolidated sand and other unconsolidated formations, such relatively nonaggressive cutters, due to the large depth-of-cut (DOC) afforded by drilling in soft formations, result in a desirable, relatively high ROP at a given WOB. However, such relatively nonaggressive cutters when encountering a relative hard formation, which it is very common to repeatedly encounter both soft and hard formations when drilling a single borehole, will experience a decreased ROP with the ROP generally becoming low in proportion to the hardness of the formation. That is, when using bits having nonaggressive cutters, the ROP generally tends to decrease as the formation becomes harder and increase as the formation becomes softer because the relatively nonaggressive cutting faces simply can not xe2x80x9cbitexe2x80x9d into the formation at a substantial DOC to sufficiently engage and efficiently remove hard formation material at a practical ROP. That is, drilling through relative hard formations with nonaggressive cutting faces simply takes too much time.
Contrastingly, cutters which provide relatively aggressive cutting action excel at engaging and efficiently removing hard formation material as the cutters generally tend to aggressively engage, or xe2x80x9cbite,xe2x80x9d into hard formation material. Thus, when using bits having aggressive cutters, the bit will often deliver a favorably high ROP, taking into consideration the hardness of the formation, and generally the harder the formation, the more desirable it is to have yet more aggressive cutters to better contend with the harder formations and to achieve a practical, feasible ROP therethrough.
It would be very helpful to the oil and gas industry, in particular, when using drag bits to drill boreholes through formations of varying degrees of hardness if drillers did not have to rely upon one drill bit designed specifically for hard formations, such as, but not limited to, consolidated sandstones and limestones and to rely upon another drill bit designed specifically for soft formations, such as, but not limited to, unconsolidated sands. That is, drillers frequently have to remove from the borehole, or trip out, a drill bit having cutters that excel at providing a high ROP in hard formations upon encountering a soft formation, or a soft xe2x80x9cstringer,xe2x80x9d in order to exchange the hard-formation drill bit with a soft formation drill bit, or vice versa, when encountering a hard formation, or hard xe2x80x9cstringer,xe2x80x9d when drilling primarily in soft formations.
Furthermore, it would be very helpful to the industry when conducting subterranean drilling operations and especially when conducting directional drilling operations, if methods were available for drilling which would allow a single drill bit be used in both relatively hard and relatively soft formations. Such a drill bit would thereby prevent an unwanted and expensive interruption of the drilling process to exchange formation-specific drill bits when drilling a borehole through both soft and hard formations. Such helpful drilling methods, if available, would result in providing a high, or at least an acceptable, ROP for the borehole being drilled through a variety of formations of varying hardness.
It would further be helpful to the industry to be provided with methods of drilling subterranean formations in which the cutting elements provided on a drag-type drill bit, for example, are able to efficiently engage the formation at an appropriate DOC suitable for the relative hardness of the particular formation being drilled at a given WOB, even if the WOB is in excess of what would be considered optimal for the ROP at that point in time. For example, if a drill bit provided with cutters having relatively aggressive cutting faces is drilling a relatively hard formation at a selected WOB suitable for the ROP of the bit through the hard formation and suddenly xe2x80x9cbreaks throughxe2x80x9d the relatively hard formation into a relatively soft formation, the aggressive cutters will likely overengage the soft formation. That is, the aggressive cutters will engage the newly encountered soft formation at a large DOC as a result of both the aggressive nature of the cutters and the still-present high WOB that was initially applied to the bit in order to drill through the hard formation at a suitable ROP but which is now too high for the bit to optimally engage the softer formation. Thus, the drill bit will become bogged down in the soft formation and will generate a TOB which, in extreme cases, will rotationally stall the bit and/or damage the cutters, the bit, or the drill string. Should a bit stall upon such a breakthrough occurring the driller must back off, or retract, the bit which was working so well in the hard formation but which has now stalled in the soft formation so that the drill bit may be set into rotational motion again and slowly eased forward to recontact and engage the bottom of the borehole to continue drilling. Therefore, if the drilling industry had methods of drilling wherein a bit could engage both hard and soft formations without generating an excessive amount of TOB while transitioning between formations of differing hardness, drilling efficiency would be increased and costs associated with drilling a wellbore would be favorably decreased.
Moreover, the industry would further benefit from methods of drilling subterranean formations in which the cutting elements provided on a drag bit are able to efficiently engage the formation so as to remove formation material at an optimum ROP yet not generate an excessive amount of unwanted TOB due to the cutting elements being too aggressive for the relative hardness of the particular formation being drilled.
The inventor herein has recognized that providing a drill bit with cutting elements having a cutting face incorporating discrete cutting surfaces of respective size and slopes to effectuate respective degrees of aggressiveness particularly suitable for use in methods of drilling through formations ranging from very soft to very hard without having to trip out of the borehole to change from a first bit designed to drill through a formation of a particular hardness to a second bit designed to drill through a formation of another particular hardness would be very beneficial. Furthermore, the disclosed method of drilling through formations of varying hardness provides enhanced cutting capability and tool face control for nonlinear drilling, as well as providing greater ROP when drilling linear borehole segments than when drilling with conventional directional or steerable bits having highly backraked cutters.
The present invention comprises a method of drilling with a rotary drag bit preferably equipped with PDC cutters wherein the respective cutting faces of at least some of the cutters include at least one radially outermost relatively aggressive cutting surface, at least one relatively less aggressive, sloped cutting surface, and at least one more centermost relatively aggressive cutting surface with each of the cutting surfaces being selectively configured, sized, and positioned such that at a given WOB, or within a given range of WOB, the extent of the DOC of each cutter is modulated in proportion to the hardness of the formation being drilled so as to maximize ROP, maximize toolface control, and minimize unwanted TOB. Thus, the present invention is particularly well-suited for drilling through adjacent formations having widely varying hardnesses and when conducting drilling operations in which the WOB varies widely and suddenly, for example, when conducting directional drilling.
The present method of drilling employing a drill bit incorporating such multi-aggressive cutters noticeably changes the ROP and TOB versus WOB characteristics of the bit by the way the DOC is varied, or modulated, in proportion to the relative hardness of the formation being drilled. In a preferred embodiment of the present invention this is achieved by the formation being engaged by at least one cutting surface having a preselected aggressiveness particularly suitable to provide an appropriate DOC at a given WOB. That is, when drilling through a relatively hard formation with embodiments of the present invention having a radially outermost positioned, aggressive primary cutting surface at or proximate the periphery of the cutter, the cutting face will aggressively engage the hard formation, by virtue of such radially outermost aggressive cutting surface having a relatively aggressive back rake angle with respect to the intended direction of bit rotation when installed in the drill bit and by virtue of the radially outermost primary cutting surface having a relatively small surface area in which to distribute the forces imposed on the bit, i.e., the WOB. Upon drilling through the relatively hard formation and encountering, for example, a formation, or stringer, of relatively softer formation, the intermediately positioned, relatively less aggressive, sloped cutting surface will become the primary cutting surface as the extent of the present DOC will have increased so that the intermediate, sloped cutting surface will engage the formation at a lesser aggressivity, in combination with the relatively more aggressive radially outermost cutting surface so as to prevent an excessive amount of TOB from being generated. Because DOC is, in effect, being modulated as a function of formation hardness, ROP is maximized without resulting in the TOB rising to a troublesome magnitude. Upon encountering a yet softer formation, the method of the present invention further calls into play the centermost, relatively more aggressive cutting surface to engage the formation at a more extensive DOC. That is, the cutting face, when encountering a relatively soft formation, will maximize the extent of DOC by not only engaging the formation with the relatively more aggressive radially outermost cutting surface and the relatively less aggressive intermediately positioned sloped cutting surface, but also with the relatively more aggressive radially centermost most cutting area so as to maximize DOC, thereby maximizing ROP and DOC while minimizing or at least limiting the TOB.
In accordance with the present invention, the relative aggressiveness of each cutting surface included on the cutting face of each cutter is selectively configured, sized, and angled, either by way of being angled with respect to the sidewall of the cutter for example, or by installing the cutter in the drill bit so as to selectively influence the backrake angle of each cutting element as installed in a drill bit used with the present method of drilling.
Optionally, at least one chamfer can be provided on or about the periphery of the radially outermost cutting surface to enhance cutter table life expectancy and/or to influence the degree of aggressivity of the radially outermost cutting surface and hence influence the overall aggressivity profile of the cutting face of a multi-aggressive cutter employed in connection with the present method of drilling.
In accordance with the present invention of drilling a borehole, a cutting element having a cutting face provided with highly aggressive cutting surfaces, or shoulders, positioned circumferentially, or radially, adjacent selected sloped cutting surfaces may be used. Alternatively, aggressive cutting faces may be positioned radially and longitudinally intermediate of selected sloped cutting surfaces of a cutting element used in drilling a borehole in accordance with the present invention. Such highly aggressive, intermediately positioned cutting surfaces, or shoulders, are preferably oriented generally perpendicular to the longitudinal axis of the cutting element, and hence will also generally, but not necessarily, be perpendicular to the peripheral sidewalls of the cutting element. Alternatively, such intermediately positioned cutting surfaces, or shoulders, may be substantially angled with respect to the longitudinal axis of the cutting element so as not to be perpendicular, yet still relatively aggressive. That is, when the cutting element is installed in a drill bit at a selected cutting element, or cutter, backrake angle, generally measured with respect to the longitudinal axis of the cutting element, the shoulder will preferably be angled so as to be highly aggressive with respect to a line generally perpendicular to the formation, as taken in the direction of intended bit rotation. Such highly aggressive shoulders serve to enhance ROP at a given WOB when drilling through formations that are of relatively intermediate hardness i.e., formations which are considered to be neither extremely hard nor extremely soft.